An automatic control and regulation exploitation experiment method and device for a heavy oil reservoir
By simulating automated control and extraction experiments of heavy oil reservoirs, the problem of extraction in heterogeneous reservoirs has been solved, achieving efficient fire-driven development and oil recovery, improving recovery rate and heat utilization rate, and reducing production costs.
Patent Information
- Application Number
- CN202510217364.3
- Authority / Receiving Office
- CN · China
- Patent Type
- Patents(China)
- Current Assignee / Owner
- Filing Date
- 2025-02-26
- Publication Date
- 2026-02-10
- Estimated Expiration
- 2045-02-26
AI Technical Summary
Heterogeneous oil reservoirs are difficult to exploit. Differences in permeability cause the injected fluid to roam erratically, making it difficult to predict the flow path. The remaining oil distribution is complex, and it is difficult to adapt the extraction technology. As a result, heavy oil reservoirs have low recovery rates, low heat utilization rates, high water content in the produced fluid, and reduced economic benefits.
An automated control and production experiment method and device for heavy oil reservoirs was adopted. The heterogeneous reservoir was simulated by physical model, and the temperature and production dynamics were monitored in real time. The gas injection scheme and control measures were adjusted to optimize the fire-driven development effect. The opening degree and frequency of production wells were adjusted by the automated control system to achieve precise fire line expansion and efficient oil production.
It improved the recovery rate of heterogeneous reservoirs, optimized the fire-driven development effect, enabled precise control of the fire line, improved heat utilization and recovery rate, reduced production costs, and avoided the lag and inaccuracy of manual control.
Smart Images
Figure CN119914228B_ABST
Abstract
Description
Technical Field
[0001] This application relates to the field of oil and gas extraction technology, and in particular to an automated control and extraction experimental method and apparatus for heavy oil reservoirs. Background Technology
[0002] The extraction of heterogeneous oil reservoirs is difficult, mainly due to the following aspects:
[0003] 1. Significant Permeability Differences: Heterogeneous reservoirs exhibit significant permeability differences across different injection and production directions. In areas of high permeability, the average pore size is large, and fluid flow resistance is low, allowing injected displacement fluids such as water and gas to easily and quickly pass through, forming "channeling" pathways. Conversely, in areas of low permeability, the pores are small, making fluid flow difficult and hindering the reach of displacement fluids. This results in the crude oil in these reservoirs being difficult to extract, limiting the overall recovery rate. For example, some reservoirs may have local permeability reaching thousands of millidarcy, while others may only have a few millidarcy. During water injection, water will preferentially flow towards the high-permeability areas, bypassing the low-permeability areas.
[0004] 2. Difficulty in predicting fluid flow paths: Due to the complex geological structure, numerous faults and fractures, and unpredictable permeability in heterogeneous reservoirs, it is difficult to accurately predict the direction of injected fluids. This makes it easy for injected fluids to fail to displace crude oil as expected during the extraction process, instead wandering aimlessly and wasting resources while failing to achieve the expected recovery rate.
[0005] 3. Complex distribution of residual oil: Heterogeneity creates a complex distribution pattern of residual oil. After a period of extraction, residual oil may be scattered in low-permeability areas, micropores, dead oil areas, or areas isolated by faults or shielding layers, making it difficult to locate precisely and thus impossible to implement targeted extraction measures. Conventional extraction methods are unlikely to extract these scattered residual oils.
[0006] 4. Difficulty in adapting extraction technologies: A single extraction technology often cannot meet the needs of heterogeneous reservoirs. For example, water injection may only be effective in some high-permeability areas; although thermal recovery can improve the fluidity of heavy oil, it is difficult to diffuse to all oil-bearing areas due to the complex permeability differences and uneven heat distribution in the reservoir; the chemical agents used in chemical flooding may also suffer from uneven injection and insufficient reaction with crude oil due to the heterogeneity of the reservoir. Combining multiple extraction technologies faces the challenges of high costs and difficulties in technology synergy.
[0007] Currently, most heavy oil reservoirs have entered the late stage of steam injection development, characterized by complex oil-water distribution, dispersed residual oil, and problems such as low heat utilization rate, high water content in produced fluids, and low crude oil recovery rate, leading to a year-on-year decline in the economic benefits of steam development. Therefore, there is an urgent need for a method to evaluate the post-development effects of heterogeneous reservoirs (especially heavy oil reservoirs) in order to determine the optimal development method suitable for heterogeneous reservoirs. Summary of the Invention
[0008] This specification provides an automated control and exploitation experimental method and apparatus for heavy oil reservoirs, used to evaluate the fire-driven development effect of target reservoirs under different gas injection schemes and control measures.
[0009] This specification provides an automated control method for heavy oil reservoirs, comprising: acquiring reservoir physical property parameters and well network distribution of the heavy oil reservoir; designing a physical model of the heavy oil reservoir based on the reservoir physical property parameters and well network distribution, wherein the physical model is a scaled-down simulation model of the actual well network distribution of the heavy oil reservoir, and the shell of the physical model forms a cavity with injection wells, production wells, and temperature monitoring wells; filling the cavity of the physical model with heterogeneous oil sands according to the reservoir physical property parameters and sealing it to simulate a heterogeneous reservoir; simulating the fire-driven development effect of the target reservoir under different gas injection schemes and control measures using the physical model, and monitoring the temperature inside the cavity of the physical model in real time through temperature monitoring wells and monitoring the gas-liquid production dynamics of each production well during the experiment; and evaluating the fire-driven development effect of the target reservoir under different gas injection schemes and control measures based on the temperature monitoring data inside the cavity of the physical model and the production volume and gas concentration monitoring data of each production well.
[0010] In some embodiments, the cavity of the physical model is filled with heterogeneous oil sands in the following manner: the heavy oil reservoir is divided into multiple permeability zones with different permeability levels; based on the division results, a baffle is set inside the cavity of the physical model to divide the cavity into multiple permeability zones; the oil sand mixing ratio corresponding to each permeability zone is determined according to the reservoir physical property parameters of the heavy oil reservoir; quartz sand, crude oil, and high-altitude soil are mixed according to the predetermined oil sand mixing ratio and then filled into the corresponding permeability zone; the mixing ratio and compaction degree corresponding to adjacent permeability zones are different to make the permeability different.
[0011] In some embodiments, during the fire-driven experiment, the following operations are performed intermittently during the fire chamber expansion phase after ignition: gas injection, hot water injection, and steam injection to improve the fire-driven recovery rate.
[0012] In some embodiments, after evaluating the fire-driven development effect of the target reservoir under different gas injection schemes and control measures based on temperature monitoring data within the physical model cavity and production volume and gas concentration monitoring data of each production well, the method further includes: adjusting at least one of the following parameters to form an extended fire-driven scheme based on the fire-driven development scheme: adjusting the depth of the injection well in the physical model cavity, the setting position of the production well on the surface of the physical model, and the depth of the production well in the physical model cavity; simulating the implementation process of each extended development scheme of the heavy oil reservoir through the physical model, monitoring the temperature within the physical model cavity in real time through temperature measuring wells during the implementation of the extended development scheme, monitoring the production volume and gas concentration of each production well, evaluating the development effect of the extended development scheme, and selecting the scheme with the highest recovery rate as the final development scheme based on the evaluation results.
[0013] In some embodiments, the physical model is further equipped with a first pressure gauge and a second pressure gauge. The first pressure gauge collects the injection pressure of the injection well, and the second pressure gauge collects the internal pressure of each production well in the connected state of its harvesting end. During the fire-drive experiment, after reaching the control timing, each production well is shut down, and the following S1 and S2 are executed cyclically: S1: When the production pressure difference reaches the upper limit pressure, the production well corresponding to the low-permeability area is opened and kept at the maximum opening degree; the production well corresponding to the high-permeability area is opened and kept at the minimum opening degree; the production pressure difference is the difference between the pressure collected by the first pressure gauge and the second pressure gauge; S2: When the production pressure difference decreases to the target pressure range, each production well is shut down.
[0014] In some embodiments, the method further includes: during the experiment, automatically controlling the on / off state of production wells in each region according to the advance status of the fire line during the fire drive process in the following manner: if the advance progress of the leading edge of the fire line in the first region exceeds that of the second region, then increasing the opening degree and frequency of the production wells corresponding to the first region, and decreasing the opening degree and frequency of the production wells corresponding to the second region.
[0015] In some embodiments, each production well has multiple opening levels; the opening level of the production well is periodically adjusted according to the actual mining situation; the method further includes: adjusting the opening level of the production well during the experiment in the following manner: if the progress of the high-permeability zone advance is greater than the preset progress, and the current opening level of the production well in the high-permeability zone is the first opening level, and it is necessary to reduce the opening level of the production well, then in the next cycle, the opening level of the production well will be reduced to the next opening level. When it is necessary to reduce the opening level of the production well again, the production well will be further adjusted to the next opening level or a fully closed state until it is no longer necessary to reduce the opening level of the production well.
[0016] In some embodiments, the method further includes: determining the timing for achieving the target control when the rate of change of the cumulative production rate of each production well decreases to a preset production rate, and / or when the oxygen concentration (rate of increase) in the produced gas concentration reaches a preset threshold.
[0017] The second aspect of this specification provides an experimental apparatus for simulating a heavy oil reservoir, comprising: a physical model for simulating a heavy oil reservoir; the physical model being a scaled-down simulation model of the actual well network distribution of the heavy oil reservoir, the shell of the physical model forming a cavity with injection wells, production wells, and temperature measurement wells; the cavity of the physical model being filled with heterogeneous oil sands according to the reservoir properties of the heavy oil reservoir and sealed to simulate a heterogeneous reservoir; and an injection-production subsystem for injecting gas from the injection wells into the cavity of the physical model and collecting and measuring the produced gas and produced fluid from each production well; the injection-production subsystem... The system includes a system for individually metering and separating the produced fluid at the production end of each production well; a monitoring subsystem for monitoring gas pressure, temperature, and gas concentration during the simulation of the heavy oil reservoir's exploitation scheme; and a control subsystem, including valves and controllers installed in each production well. The controllers observe the production status of production wells in different permeable areas in real time based on the metering results of the injection-production subsystems, determine the degree of production in different permeable areas, send control commands to the valves based on the production rate of each production well to adjust the progress of the fire line expansion, and send control commands to the valves to realize the automated control exploitation experimental method for heavy oil reservoirs as described in any of the first aspects.
[0018] The automated control experimental method and apparatus for heavy oil reservoirs provided in this manual can conduct experiments on a single injection and multiple recovery production scheme using a physical model of the heavy oil reservoir, thereby studying the dynamic evolution law of the fire cavity in heterogeneous reservoirs. The model's heterogeneity can be optimized and adjusted according to actual formation parameters, and the model can simulate formation heterogeneity with arbitrary parameters. The simulation system can solve the problems of time-consuming, labor-intensive, untimely, and inaccurate manual control, achieving the technical effect of "precisely determining the combustion state of fire-driven oil recovery and accurately controlling the fire-driven oil recovery process." It can study the impact of different control schemes on the fire front advance speed and swept volume, and can detect the dynamic changes in fire front development during fire-driven oil recovery in real time, control and guide the fire front direction in real time, and control and improve the swept volume of the fire cavity, thereby increasing the reservoir utilization rate. Attached Figure Description
[0019] To more clearly illustrate the technical solutions in the embodiments of this application or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments recorded in this application. For those skilled in the art, other drawings can be obtained from these drawings without creative effort.
[0020] Figure 1 This document provides a flowchart illustrating an automated control experimental method for heavy oil reservoirs.
[0021] Figure 2 A schematic diagram of a physical model of a heavy oil reservoir;
[0022] Figure 3 A flowchart illustrating another automated control experimental method for heavy oil reservoirs provided in this specification;
[0023] Figure 4 A flowchart of a control method for a fire-driven mining scheme;
[0024] Figure 5 A flowchart illustrating another control method for fire-driven mining schemes;
[0025] Figure 6 A schematic diagram of the various structures used to control the opening degree of production wells;
[0026] Figure 7 This is a schematic diagram of an automated control experimental device for a heavy oil reservoir.
[0027] Figure 8 This is a schematic diagram of a proportional solenoid valve. Detailed Implementation
[0028] To enable those skilled in the art to better understand the technical solutions in this application, the technical solutions in the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only a part of the embodiments of this application, and not all of the embodiments. Based on the embodiments in this application, all other embodiments obtained by those skilled in the art without creative effort should fall within the scope of protection of this application.
[0029] To improve the recovery rate of heterogeneous oil reservoirs, this specification provides an automated control and exploitation experimental method for heavy oil reservoirs, such as... Figure 1 As shown, the method includes the following steps S10 to S40.
[0030] S10: Obtain reservoir physical properties and well pattern distribution of heavy oil reservoirs.
[0031] Reservoir physical properties can include porosity, permeability, saturation, pore structure parameters (such as pore radius and pore throat ratio), and compressibility (such as rock compressibility and fluid compressibility).
[0032] Well network distribution refers to the distribution of oil wells on the reservoir plane, which may include the location of production wells, the relative orientation between injection wells and production wells, etc.
[0033] S20: Design a physical model of a heavy oil reservoir based on the reservoir physical properties and well network distribution. The physical model is a scaled-down simulation model of the actual well network distribution of the heavy oil reservoir. The shell of the physical model forms a cavity with injection wells, production wells, and temperature measurement wells. The cavity of the physical model is filled with heterogeneous oil sands according to the reservoir physical properties and sealed to simulate a heterogeneous oil reservoir.
[0034] The physical model of a heavy oil reservoir is a solid model. For example... Figure 2 As shown, G represents a chimney well, N1, N2, and N3 represent horizontal production wells, H represents a gas injection well, and P represents a pressure gauge used to measure gas pressure. The physical model includes a shell, which can be made of Hastelloy, a high-temperature and high-pressure resistant alloy capable of withstanding temperatures up to 700°C. The shell forms an open cavity, with an end cap and flange at the opening. The flange can be made of high-temperature resistant stainless steel, and the shell and end cap are connected via the flange. The shell, end cap, and flange together form a closed cavity to simulate the actual high-temperature and high-pressure environment in heavy oil reservoirs.
[0035] The inner wall of the cavity can be evenly coated with a high-temperature resistant fireproof coating to reduce heat loss, and a constant temperature insulation jacket can be installed on the outside of the shell to compensate for heat loss.
[0036] The casing is equipped with an injection well, a production well, a chimney well, and a temperature measuring well. An electric igniter can be embedded in the injection well, which is installed within the liner. The bottom of the liner has multiple air holes for air injection. Both the injection well and the production well are equipped with high-temperature resistant stainless steel screens to prevent sand from clogging the pipelines.
[0037] The number and location of production wells and chimney wells can be determined based on the actual distribution of the heavy oil reservoir well network. Multiple temperature sensing wells can be installed (e.g., one well approximately every 10 cm), extending from the bottom to the top of the cavity, and arranged in parallel. Multiple thermocouples at different heights are installed in each temperature sensing well, forming multiple temperature sensing layers at different distances from the production plane. In other words, the temperature can be measured at multiple points on multiple planes within the cavity, and at multiple locations on each plane.
[0038] The cavity of the physical model is filled with heterogeneous oil sand in the manner described in S21 and S22 below.
[0039] S21: Divide the heavy oil reservoir into multiple permeable regions with different permeability levels. Based on the division results, set baffles inside the cavity of the physical model to divide the cavity into multiple permeable regions.
[0040] After obtaining the reservoir physical properties of heavy oil reservoirs, multiple permeability zones with different permeability gradients can be divided based on these properties. The specific number of permeability zones and the range of permeability values for each zone can be determined according to the actual situation. The permeability value spans for different permeability gradients can vary.
[0041] S22: Determine the particle size of the mixture and the oil sand mixing ratio corresponding to each permeable zone based on the reservoir physical property parameters of the heavy oil reservoir. Mix quartz sand, crude oil and kaolin according to the predetermined oil sand mixing ratio and fill them into the corresponding permeable zone. The mixing ratio and compaction degree of adjacent permeable zones are different to make the permeability different.
[0042] The particle size and oil-sand mixing ratio of the mixture can be determined based on various reservoir properties such as permeability, porosity, saturation, and pore structure parameters. For example, quartz sand with different mesh sizes can be mixed with crude oil and kaolin to obtain three mixed filling materials corresponding to different permeability levels.
[0043] S30: The temperature inside the physical model cavity is monitored in real time using the temperature measurement well of the physical model, and the liquid production and gas concentration of each production well are also monitored.
[0044] The fire-drive experiment may include the following steps: opening the high-pressure nitrogen cylinder, injecting nitrogen into the cavity of the physical model through the pressure stabilizing device, and opening the back pressure valve to adjust the pressure in the cavity of the physical model; after the back pressure of the physical model is stabilized, preheating the physical model to the preset temperature through the heating rod; after the preheating reaches the preset requirements, opening each production well, opening the high-pressure air cylinder to inject air into the cavity of the physical model and igniting it to simulate the fire-drive mining scheme.
[0045] In some embodiments, during the fire chamber expansion phase of the fire-driven experiment, the following operations may be performed intermittently: gas injection, hot water injection, and steam injection. Here, intermittent execution of A and B means that A is executed for a period of time, then B is executed, then B is executed for a period of time, then A is executed again, and so on, with A, B, B, A… being executed alternately.
[0046] By injecting hot water and using steam control methods, the viscosity of crude oil can be reduced, its fluidity enhanced, and the seepage conditions of the oil reservoir improved, thereby increasing the recovery rate of crude oil.
[0047] S40: Based on the temperature monitoring data within the physical model cavity, the production volume of each production well, and the production gas concentration monitoring data, evaluate the fire-driven development effect of the target reservoir under different gas injection schemes and control measures.
[0048] The effectiveness of fire-driven exploitation can be evaluated based on the gas-liquid production dynamics of each production well. Simultaneously, it's necessary to consider the temperature changes within the physical model's cavity to determine whether the expected level of fire-driven exploitation has been achieved. For example, if the maximum temperature in most areas of the physical model's cavity reaches a certain high-temperature value, but the maximum temperature in one area differs significantly from that value, then it can be determined that the fire front did not pass through that area, indicating insufficient exploitation in that area.
[0049] In some embodiments, such as Figure 3 As shown, after S40, there are also S50 to S80.
[0050] S50: Based on the fire-driven mining scheme, adjust the following parameters to form an extended mining scheme: the depth of the injection well in the physical model cavity, the location of the production well on the surface of the physical model, and the depth of the production well in the physical model cavity.
[0051] Normally, once the shell of a physical model is formed, its structure cannot be changed. Parameter changes can be achieved by creating multiple physical models with different shell structures. Alternatively, interfaces for parameter modification can be pre-installed on the shell of the physical model to allow for flexible parameter adjustments. For example, spare production wells can be pre-installed, sealed when not in use, and opened when needed.
[0052] S60: The implementation process of each extended mining scheme is simulated using a physical model. During the implementation of the extended mining scheme, the temperature inside the physical model cavity is monitored in real time through temperature measurement wells, and the production volume and gas concentration of each production well are also monitored.
[0053] S70: Based on the temperature monitoring data within the physical model cavity, and the monitoring data on the production volume and gas concentration of each production well, evaluate the mining effectiveness of the extended mining scheme.
[0054] S80: Based on the evaluation results, the scheme with the highest recovery rate is selected as the final mining scheme.
[0055] In some embodiments, the physical model is further provided with a first pressure gauge and a second pressure gauge. The first pressure gauge collects the injection pressure of the injection well, and the second pressure gauge collects the internal pressure of each production well when the harvesting ends are connected.
[0056] The fire-driven extraction scheme aims to extract as much remaining oil as possible from the reservoir. Non-uniform expansion of the fire chamber often leads to a low sweep efficiency and low oil recovery rate. Effective control measures can improve the non-uniform expansion behavior of the fire chamber, increase its volumetric sweep efficiency, and enhance the recovery rate of the fire-driven extraction technology. Traditional fire-driven extraction control measures rely on manual adjustment, which is characterized by sluggish control, inaccurate control, low efficiency, complex operation, time-consuming and labor-intensive processes, and the potential for injury if not handled properly. The physical model simulation of the fire-driven extraction scheme in this design not only ensures safety but also enables automated, high-precision control.
[0057] like Figure 4 As shown, the fire-driven mining scheme includes: after reaching the control time, shutting down each production well and cyclically executing the following S1 and S2.
[0058] S1: When the production pressure difference reaches the upper limit pressure, open the production well corresponding to the low permeability area and keep the opening at the maximum; open the production well corresponding to the high permeability area and keep the opening at the minimum; the production pressure difference is the difference between the pressure collected by the first pressure gauge and the second pressure gauge.
[0059] During fire-driven experiments, high-temperature combustion alters the properties of crude oil, reducing its viscosity and making it more fluid. Generally, crude oil experiences less resistance flowing through high-permeability regions than in low-permeability regions, making it easier to create advantageous channels for fire-driven advance.
[0060] High-permeability zones and low-permeability zones are relative terms. High-permeability zones are those with the highest permeability among all permeability zones, while low-permeability zones are those with the lowest permeability among all permeability zones.
[0061] The aforementioned upper limit pressure can be the maximum pressure that the physical structure of the physical model can withstand during operation, or it can be a relatively large pressure value determined empirically to improve the recovery rate. For example, the upper limit pressure can be 1200 kPa.
[0062] S2: Once the production pressure differential drops to the target pressure range, shut down all production wells.
[0063] The intermittent control methods described in S1 and S2 above utilize disturbances in the flow and thermal fields to reduce or slow down the advance speed of the fire front in the dominant channel (high-permeability zone), while increasing the advance speed and coverage area of the fire front in the low-permeability zone. These intermittent control methods can reduce the fluid velocity in the high-permeability zone, slow down the combustion reaction rate, prevent damage to the formation rock structure due to excessively high temperatures in the high-permeability zone, reduce the advance speed of the fire front in the high-permeability zone, weaken the disturbance of the flow and thermal fields in the high-permeability zone, increase the combustion reaction rate in the low-permeability zone, and improve the disturbance of the flow and thermal fields and the advance speed of the fire front in the low-permeability zone. This helps to improve the overall effective utilization of heat, reduce gas channeling, improve the uniform diffusion of heat within the reservoir, reduce uneven pressure distribution within the reservoir, and improve displacement efficiency.
[0064] In some embodiments, such as Figure 5 As shown, between S1 and S2, there is also S3: if the advance of the front edge of the fire line in the high-permeability zone exceeds that in the low-permeability zone, then the opening degree and frequency of the production well corresponding to the low-permeability zone are increased, and the opening degree and frequency of the production well corresponding to the high-permeability zone are decreased.
[0065] After ignition within the physical model cavity, the fire front advances with the flow of air. However, due to differences in permeability, the air velocity differs between high-permeability and low-permeability regions, resulting in varying advance rates of the fire front in heavy oil reservoirs. Without intervention in the advance of the fire front, it may prematurely approach the vicinity of the production well in the high-permeability region, causing the fire flooding experiment (fire channeling or gas channeling) to end prematurely. In this scenario, a significant amount of unexploited oil and gas may remain in the low-permeability region, leading to a lower overall recovery rate for the heavy oil reservoir.
[0066] When production wells in high-permeability and low-permeability zones have the same opening degree, air diffusion is better in high-permeability zones, forming an advantageous channel for air circulation, thus resulting in faster advance speed of the fire front edge in high-permeability zones.
[0067] Increasing the opening degree and frequency of production wells in low-permeability areas can enhance air diffusion in those areas. However, during fire flooding experiments, the advance path of the fire front is not only affected by air diffusion in low-permeability areas but also by air diffusion in high-permeability areas. For example, if air diffusion is good in the dominant channel (i.e., the high-permeability area), even if air diffusion is improved in the non-dominant channel (i.e., the low-permeability area), it will not increase the fire front advance speed in the low-permeability area or decrease it in the high-permeability area, thus failing to achieve the desired fire front traction effect. This scheme gradually increases the opening degree and frequency of low-permeability production wells while gradually decreasing the opening degree and frequency of high-permeability production wells, achieving the aforementioned desired fire front traction effect, thereby improving the fire flooding efficiency in low-permeability areas and the production rate of high-permeability production wells.
[0068] The valve opening degree refers to the opening degree of the valves in the production wells. These valves are proportional solenoid valves whose opening degree can be controlled by input signals. Each proportional solenoid valve is controlled by the same controller. This controller synchronously controls the opening degree of the proportional solenoid valves in each production well based on temperature monitoring data within the physical model cavity. The controller can also control the opening degree of the proportional solenoid valves in each production well in conjunction with the production pressure differential, the production fluid rate of each production well, and the concentration of produced gas. This controller includes a PWM electronic controller and a computer. Figure 6 As shown, each proportional solenoid valve corresponds to a PWM electronic controller. The valve opening of the proportional solenoid valve is adjusted by the PWM electronic controller, and control commands are sent to each PWM electronic controller by the computer.
[0069] The advancement progress of the leading edge of the fire line can be the ratio of the advancement distance to the overall length in the injection-production connection direction. Temperature measurement wells can be set at equal intervals, with thermocouples installed at different heights within each well, forming multiple temperature measurement layers at varying distances from the production plane. In this case, each thermocouple can be numbered, and the correspondence between thermocouple numbers and positions can be predetermined. The position of the leading edge of the fire line can be determined based on the thermocouple readings, thereby determining the advancement distance of the leading edge.
[0070] When the position of the leading edge of the fire wire is determined to be near any production well by the collection values of each thermocouple, the above-mentioned fire wire traction control process can be ended, and nitrogen gas can be injected into the physical model to extinguish the flame in the cavity.
[0071] In some embodiments, the timing for regulation is determined when the rate of change of the cumulative production rate of each production well decreases to a preset production rate (e.g., the preset production rate may be 0, or a small value close to 0), and / or when the oxygen concentration (rate of increase) in the produced gas concentration reaches a preset threshold.
[0072] In some embodiments, during the experiment, the on / off state of production wells in each region is automatically controlled according to the advance status of the fire line during the fire drive process in the following manner: if the advance progress of the leading edge of the fire line in the first region exceeds that of the second region, the opening degree and frequency of the production wells corresponding to the first region are increased, and the opening degree and frequency of the production wells corresponding to the second region are decreased.
[0073] The terms "first region" and "second region" are used to refer to two different infiltration areas only, and do not specifically refer to any one region.
[0074] In some embodiments, each production well has multiple opening levels; the opening level of the production well is periodically adjusted according to the actual mining situation.
[0075] During the experiment, the opening degree of the production well was adjusted in the following way: If the progress of the high-permeability zone advance is greater than the preset progress, and the current opening degree of the production well in the high-permeability zone is the first opening degree level, and it is necessary to reduce the opening degree of the production well, then in the next cycle, the opening degree of the production well will be reduced to the next opening degree level. When it is necessary to reduce the opening degree of the production well again, the production well will be further adjusted to the next opening degree level or fully closed, until it is no longer necessary to reduce the opening degree of the production well.
[0076] For example, production wells can be set with multiple settings such as fully closed, 1 / 8, 1 / 4, 1 / 2, 3 / 4, and fully open. The opening degree can be adjusted periodically according to the actual production situation. For example, if the front line advances too quickly in a high-permeability area, and the current opening degree of the production well in the high-permeability area is 1 / 4, and it is necessary to reduce the opening degree of the production well, then in the next cycle, the opening degree of the production well can be adjusted to 1 / 5. When it is necessary to reduce the opening degree of the production well again, the production well can be adjusted to a full 1 / 8 or fully closed state until it is necessary to reduce the opening degree of the production well, so as to ensure that the front line advances evenly and stably in the high-permeability and low-permeability areas of the target reservoir.
[0077] This specification provides an automated control and production experimental device for heavy oil reservoirs, including a physical model for simulating heavy oil reservoirs, an injection and production subsystem, a monitoring subsystem, and a control subsystem.
[0078] The physical model of the heavy oil reservoir is a scaled-down simulation model of the actual well network distribution. The shell of the physical model forms a cavity with injection wells, production wells, and temperature measurement wells. The cavity of the physical model is filled with heterogeneous oil sands according to the reservoir properties of the heavy oil reservoir and sealed to simulate the heterogeneous reservoir.
[0079] The injection-production subsystem is used to inject gas from the injection well into the cavity of the physical model, and to collect and measure the produced gas and produced fluid from each production well. The injection-production subsystem separately measures and separates the produced fluid at the production end of each production well.
[0080] The monitoring subsystem is used to monitor gas pressure, temperature, and gas concentration during the simulation of heavy oil reservoir exploitation schemes.
[0081] The control subsystem includes valves and controllers installed in each production well. The controllers observe the production status of production wells in different permeable areas in real time based on the metering results of the injection and production subsystem, determine the production degree of different permeable areas, send control commands to the valves according to the production rate of each production well to adjust the progress of the fire line expansion, and send control commands to the valves to realize the above-mentioned automated control and production experimental method for heavy oil reservoirs.
[0082] Figure 7 This is a schematic diagram of an automated control and production experimental device for a heavy oil reservoir. In the diagram, 1 represents a high-pressure nitrogen cylinder, 2 represents a high-pressure air cylinder, 3 represents a ball valve, 4 represents a gas flow meter, 5 represents a physical model used to simulate the heavy oil reservoir, 6 represents a pressure stabilizing tank, 7 represents a first pressure gauge, 8 represents a computer or controller, 9 represents a thermocouple, 10 represents a proportional solenoid valve, 11 represents a horizontal production well, 12 represents a second pressure gauge, 13 represents a back pressure regulating valve, 14 represents a gas-liquid separator, 15 represents a gas analyzer, and 16 represents a flue gas processor.
[0083] High-pressure nitrogen cylinder 1 and high-pressure air cylinder 2 are connected to gas flow meter 4 via ball valve 3. The gas flow enters the physical model 5, which simulates a heavy oil reservoir, through pressure stabilizing tank 6. First pressure gauge 7 is used to measure the injection pressure of the injection well in physical model 5, and second pressure gauge 12 is used to measure the internal pressure of each production well in the connected state of the production section. 132 thermocouples 9 are installed inside the cavity of physical model 5 and inserted into temperature measuring wells for temperature detection. Proportional solenoid valve 10 is connected to horizontal production well 11. Computer or controller 8 is used to send control commands to proportional solenoid valve 10 to control the opening degree of horizontal production well. Back pressure regulating valve 13 is used to maintain the pressure stability of pipelines and model. Gas-liquid separator 14 separates produced gas and produced liquid, and the separated gas is metered using a liquid collection cylinder. Gas analyzer 15 is connected to the gas-liquid separator at one end and to flue gas processor 16 at the other end. Gas analyzer 15 detects the separated flue gas, and flue gas processor 16 collects and processes the flue gas discharged from gas analyzer 15.
[0084] Figure 7 The high-pressure nitrogen cylinder 1, high-pressure air cylinder 2, ball valve 3, pressure stabilizing tank 6, gas-liquid separator 14, gas analyzer 15, and flue gas processor 16 are components of the injection and production subsystem; the gas flow meter 4, injection end pressure gauge 7, thermocouple 9, and production end pressure gauge 12 are components of the monitoring subsystem; and the proportional solenoid valve 10, back pressure regulating valve 13, and computer 8 are components of the control subsystem.
[0085] like Figure 6As shown, in the automated control method for heavy oil reservoirs, the controller includes a PWM electronic controller. The horizontal production well is connected to a proportional solenoid valve, which is connected to the PWM electronic controller. The PWM electronic controller receives control commands sent by the computer to control the opening of the proportional solenoid valve and adjust the flow rate of the proportional solenoid valve in the horizontal well.
[0086] like Figure 8 As shown, a proportional solenoid valve can be composed of a proportional amplifier, a proportional electromagnet, and a hydraulic control valve. The proportional solenoid valve receives a PWM command signal, which is amplified by the proportional amplifier and outputs a proportional current to the proportional electromagnet of the proportional solenoid valve. The proportional electromagnet outputs force and moves the valve core position proportionally, thereby controlling the flow rate of the fluid and thus controlling the flow velocity of the produced liquid.
[0087] The gas analyzer 15 can include multiple gas monitoring modules such as O2, CO, CO2, CH4, and H2. The flue gas separated by the gas-liquid separator 14 enters the gas analyzer 15. The gas analyzer 15 monitors the concentration data of the gases produced during the fire driving process in real time to help determine the fire driving combustion status. Specifically, when the oxygen component is 0, it indicates that the fire driving combustion is in the high-temperature combustion stage and the fire driving combustion status is optimal, with the fire line advancing steadily forward.
[0088] The flue gas processor 16 collects the exhaust gas flowing through the gas analyzer 15. The flue gas processor 16 adsorbs and removes harmful substances from the exhaust gas. After the exhaust gas is treated to meet the standards, it is discharged into the atmosphere, reducing pollution and protecting the environment.
[0089] The specific experiments used to verify the heavy oil reservoir exploitation method provided in this specification through the above-mentioned heavy oil reservoir exploitation experimental apparatus may include the following nine steps.
[0090] Step 1: Preparation of Experimental Samples
[0091] According to the design ratio, add quartz sand, heavy oil and kaolin respectively, and turn on the heating function of the mixer. Considering that the oil sample has a high viscosity, the mixing time should be at least 4 hours to ensure that the oil and sand are mixed evenly.
[0092] Step Two: Filling with Oil Sand and Checking for Sealing
[0093] Spread the well-mixed oil sand evenly into the physical model (large model 5), then compact it evenly with a plunger. After filling the oil sand, apply a layer of insulating cement to the top of the oil sand to prevent air leakage. Finally, put the physical model (large model 5) on top and connect the inlet and outlet pipelines, then check for a tight seal.
[0094] Step 3: Set up the temperature measuring thermocouple
[0095] Each temperature measuring well was fitted with three thermocouples at different heights, forming five temperature measuring layers at different heights, which were used to detect temperature changes inside the model.
[0096] Step 4: Preheating
[0097] Open the high-pressure nitrogen cylinder 1. Nitrogen gas flows into the gas flow meter 4 and then into the physical model 5 through the pressure stabilizing tank 6. Open the back pressure valve 13 to adjust the model pressure. Once the back pressure of the physical model 5 is stable, start the preheating program. During preheating, set the igniter temperature to 200℃~350℃ and the gas injection rate to 1.5L / min. When the oil sand near the igniter rises to approximately 300℃, the preheating of the physical model 5 is complete. During preheating, the external heating jacket of the physical model needs to be turned on to compensate for heat loss in real time.
[0098] Step 5: Air transfer and ignition
[0099] After preheating, the nitrogen valve is closed and the high-pressure air cylinder 2 is opened for air injection and ignition. During this process, the igniter temperature is gradually increased to 600℃, and the injection rate is gradually increased to 2L / min. Simultaneously, the production pressure difference is recorded based on the values collected by the first pressure gauge 7 and the second pressure gauge 12, the values collected by each thermocouple in the temperature measuring well 9 are recorded, and the volume fraction change of the produced gas is recorded based on the analysis value of the gas analyzer 16.
[0100] Step Six: Determine the Timing of Regulation
[0101] The timing for achieving the target control is determined when the rate of change of the cumulative fluid production rate of each production well decreases to 0.
[0102] Step 7: Automated Control of Fire Drive
[0103] The specific operation of the automated control system for fire-driven operations is as follows:
[0104] Once the timing for regulation is reached, regulation is implemented, and intermittent measures are taken. It is necessary to maintain the synchronous and stable advancement of the fire line and oil wall in the low-permeability and high-permeability areas according to the production pressure difference. The regulation pressure difference range is maintained between 300 kPa and 900 kPa, so that the magnitude and frequency of the pressure change over time during fire-driven regulation are maintained within a reasonable range, thereby forming a stable oil wall that moves towards the production well.
[0105] When the regulation timing is reached, first start to shut down the production wells in the low-permeability, medium-permeability, and high-permeability areas. When the production pressure reaches the upper limit pressure of 1200 kPa in the fire flooding process, open the production well (N1) in the low-permeability area, keep it fully open, open the production well (N3) in the medium-permeability area with a 1 / 2 opening, open the production well (N2) in the high-permeability area with a 1 / 4 opening. When the production pressure drops to the P1 value, where 300 kPa < P1 < 900 kPa, shut down the production wells N1, N2, and N3 in the low-permeability, medium-permeability, and high-permeability areas; then when the production pressure difference rises again to 1200 kPa, open the production well (N1) in the low-permeability area, keep it fully open, open the production well (N3) in the medium-permeability area with a 1 / 2 opening, open the production well (N2) in the high-permeability area with a 1 / 4 opening. When the production pressure difference drops to P1, shut down the production wells N1, N2, and N3 in the low-permeability, medium-permeability, and high-permeability areas, and then repeat the operation periodically to make the fire front steadily advance towards the low-permeability and high-permeability production wells evenly. During the intermittent regulation process, if the front edge of the fire line in the low-permeability area still lags behind the progress of the front edge of the fire line in the high-permeability area, or the advancing speed of the fire line in the high-permeability area is too fast and greater than that in the low-permeability area, then it is necessary to adjust the opening and frequency in the high-permeability area, that is, reduce the opening or opening frequency of the production wells in the high-permeability area. At this time, the regulation measures are as follows:
[0106] When the production pressure difference reaches the upper limit pressure of 1200 kPa, open the production well (N1) in the low-permeability area, keep it fully open, open the production well (N3) in the medium-permeability area with a 1 / 4 opening, open the production well (N2) in the high-permeability area with a 1 / 8 opening. When the production pressure difference drops to the P1 value, shut down the production wells in the low-permeability, medium-permeability, and high-permeability areas; then when the production pressure difference rises again to 1200 kPa, open the production well in the low-permeability area, open the production well (N3) in the medium-permeability area with a 1 / 4 opening, open the production well in the high-permeability area with a 1 / 8 opening. When the production pressure difference drops to P1, shut down the production wells N1, N2, and N3 in the low-permeability, medium-permeability, and high-permeability areas again, and then repeat the operation periodically in real time to detect the position of the front edge of the fire line. If the front edge of the fire line in the high-permeability area is still advancing too fast, then shut down the production wells in the high-permeability area and only intermittently regulate the production wells in the low-permeability and medium-permeability areas. The opening and intermittent closing frequency of the production wells in the low-permeability and medium-permeability areas are adjusted as follows:
[0107] When the production pressure difference reaches the upper limit pressure of 1200 kPa, open the production well N1 in the low-permeability area, keep it fully open, the production well N2 in the high-permeability area remains in a normally closed state, and the production well N3 in the medium-permeability area is opened with a 1 / 4 opening. When the production pressure difference drops to the P1 value, shut down N1 and N3; then when the production pressure difference rises again to 1200 kPa, open N1, keep it fully open, N2 remains closed, and N3 is opened with a 1 / 4 opening. When the production pressure difference drops to P1, shut down N1 and N3 again; then repeat the above operation until the fire line is stably and fully advanced to the vicinity of the production wells in the low, medium, and high-permeability areas, and then end the regulation.
[0108] The P1 value can be adjusted according to the actual situation. When the outlet fluid rate is stable, the P1 value can be appropriately reduced, that is, the injection-production pressure difference can be increased. The opening degree and frequency of the production well can be adjusted in real time according to the fire driving effect until the fire line steadily advances to the vicinity of the production well, and the control ends.
[0109] Step 8: Turn off the engine
[0110] When the oxygen concentration of the produced gas exceeds the preset concentration value or the combustion front approaches the production well, the air injection is stopped and nitrogen is injected to extinguish the flame and terminate the experiment.
[0111] The automated control and production experimental method and apparatus for heavy oil reservoirs provided in this manual can conduct experiments on a single injection and multiple production scheme using a physical model of the heavy oil reservoir, thereby studying the dynamic evolution law of the fire cavity in heterogeneous reservoirs. The model's heterogeneity can be optimized and adjusted according to actual formation parameters, and the model can simulate formation heterogeneity with arbitrary parameters. The experimental method can solve the problems of time-consuming, labor-intensive, untimely, and inaccurate manual control, achieving the technical effect of accurately determining the combustion state of production wells and accurately controlling the fire-driven oil production process. It can detect the dynamic changes in the development of the fire line in real time during the fire-driven process, control and guide the direction of the fire line in real time, and control and increase the swept volume of the fire cavity, thereby improving the reservoir utilization rate.
[0112] The experimental methods and apparatus for heavy oil reservoir development provided in this manual possess an extremely wide range of applications and outstanding versatility. They can not only effectively conduct heavy oil fire flooding experiments, deeply exploring the complex physicochemical changes, displacement mechanisms, and related development characteristics of heavy oil under fire flooding, but also demonstrate strong adaptability and reliability in light oil air injection flooding experiments. In light oil air injection flooding experiments, the experimental apparatus can accurately simulate the actual geological environment and conditions of light oil reservoirs, strictly controlling various parameters of air injection, such as flow rate, pressure, and temperature, thereby meticulously observing the interaction process between light oil and injected air under different conditions. Precise monitoring and analysis of various data indicators during the experimental process, including but not limited to changes in light oil production, gas composition changes, and displacement efficiency at different stages, can provide crucial and comprehensive theoretical basis and practical guidance for the application of light oil air injection flooding technology in actual oilfield development, powerfully promoting the efficient development and utilization of light oil resources, and greatly expanding the application value and depth of the experimental apparatus in the field of petroleum extraction technology research.
[0113] Although this application has been described through embodiments, those skilled in the art will know that this application has many modifications and variations without departing from the spirit of this application, and it is intended that the appended claims cover such modifications and variations without departing from the spirit of this application.
Claims
1. An automated control and exploitation experimental method for heavy oil reservoirs, characterized in that, include: Obtain reservoir physical properties and well pattern distribution of heavy oil reservoirs; A physical model of a heavy oil reservoir is designed based on the reservoir physical properties and well pattern distribution. The physical model is a scaled-down simulation model of the actual well pattern distribution of the heavy oil reservoir. The shell of the physical model forms a cavity with injection wells, production wells, and temperature measurement wells. The cavity of the physical model is filled with heterogeneous oil sands according to the reservoir physical properties and sealed to simulate a heterogeneous reservoir. The cavity of the physical model is filled with multiple permeable zones according to the permeability differences of the heavy oil reservoir. A simulated fire-drive experiment was conducted using the physical model. During the experiment, the temperature inside the physical model cavity was monitored in real time using a temperature measuring well, and the production volume and gas concentration of each production well were also monitored. Based on the temperature monitoring data within the physical model cavity, and the production volume and gas concentration monitoring data of each production well, the fire-driven development effect of the target reservoir under different gas injection schemes and control measures is evaluated. The fire-driven experimental mining scheme includes: after reaching the control timing, shutting down each production well and cyclically executing S1 and S2, wherein S1: when the production pressure difference reaches the upper limit pressure, opening the production well corresponding to the low permeability area and maintaining the maximum opening degree; opening the production well corresponding to the high permeability area and maintaining the minimum opening degree; S2: when the production pressure difference decreases to the target pressure range, shutting down each production well. The timing of the regulation includes when the rate of change of the cumulative production rate of each production well decreases to a preset production rate, and / or when the oxygen concentration in the produced gas reaches a preset threshold. Each production well has multiple opening levels; the opening level of the production well is adjusted periodically according to the actual mining situation. The method further includes adjusting the opening degree of the production well during the experiment as follows: if the progress of the high-permeability zone advance is greater than the preset progress, and the current opening degree of the high-permeability zone production well is at the first opening degree level, and it is necessary to reduce the opening degree of the high-permeability production well, then in the next cycle, the opening degree of the high-permeability zone production well will be reduced to the next opening degree level; if it is necessary to reduce the opening degree of the high-permeability zone production well again, the high-permeability zone production well will be further adjusted to the next opening degree level or fully closed, until it is no longer necessary to reduce the opening degree of the high-permeability zone production well. The method further includes: during the experiment, automatically controlling the switching status of production wells in each area based on the fire-drive advance status in the following manner: If the advance progress of the leading edge of the first zone exceeds that of the second zone, then the opening degree of the production well corresponding to the first zone is reduced, and the opening degree of the production well corresponding to the second zone is increased.
2. The method according to claim 1, characterized in that, The cavity of the physical model is filled with heterogeneous oil sand in the following manner: The heavy oil reservoir is divided into multiple permeable regions with different permeability levels. Based on the division results, baffles are set inside the cavity of the physical model to divide the cavity into multiple permeable regions. Based on the reservoir physical properties of heavy oil reservoirs, the oil-sand mixing ratio corresponding to each permeable zone is determined. Quartz sand, crude oil and kaolin are mixed according to the predetermined oil-sand mixing ratio and then filled into the corresponding permeable zone. The different mixing ratios and compaction degrees of adjacent permeable zones result in different permeability.
3. The method according to claim 1, characterized in that, During the fire-driven experiment, at least one of the following operations is performed intermittently during the fire chamber expansion phase: gas injection, hot water injection, or steam injection.
4. The method according to claim 1, characterized in that, After evaluating the fire-flooding development effect of the target reservoir under different gas injection schemes and control measures based on the temperature monitoring data within the physical model cavity and the production volume and gas concentration monitoring data of each production well, the process also includes: Based on the fire-driven mining scheme, the following parameters are adjusted to form an extended mining scheme: the depth of the injection well in the physical model cavity, the location of the production well on the surface of the physical model, and the depth of the production well in the physical model cavity. The implementation process of various extended production schemes for heavy oil reservoirs is simulated by physical models. During the implementation of the extended production schemes, the temperature inside the physical model cavity is monitored in real time by temperature measurement wells, and the production volume and gas concentration of each production well are also monitored. Based on the temperature monitoring data within the physical model cavity, and the liquid production and gas concentration monitoring data of each production well, the mining effectiveness of the extended mining scheme is evaluated. Based on the evaluation results, the scheme with the highest recovery rate was selected as the final exploitation scheme for the target reservoir.
5. An automated control and exploitation experimental device for heavy oil reservoirs, characterized in that, include: A physical model for simulating heavy oil reservoirs; the physical model is a scaled-down simulation model of the actual well network distribution of heavy oil reservoirs, and the shell of the physical model forms a cavity with injection wells, production wells and temperature measurement wells; the cavity of the physical model is filled with heterogeneous oil sands according to the reservoir physical property parameters of heavy oil reservoirs and is sealed to simulate heterogeneous oil reservoirs. The injection-production subsystem is used to inject gas from the injection well into the cavity of the physical model, and to collect and measure the produced gas and produced fluid from each production well; the injection-production subsystem separately measures and separates the produced fluid at the production end of each production well. The monitoring subsystem is used to monitor gas pressure, temperature, and gas concentration during the simulation of heavy oil reservoir exploitation schemes. The control subsystem includes valves and controllers installed in each production well. The controllers observe the production status of production wells in different permeable areas in real time based on the metering results of the injection-production subsystem, determine the production degree of different permeable areas, send control commands to the valves according to the production rate of each production well to adjust the progress of the fire line expansion, and send control commands to the valves to realize the automated control and production experimental method for heavy oil reservoirs as described in any one of claims 1 to 4.